UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
_____________________
FORM 10-Q
[ X ] Quarterly Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934 for the quarter ended September 30, 1999
[ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934 for the transition period from
______________________ to ______________________
Commission File Number: 033-73160
CALPINE CORPORATION
(A Delaware Corporation)
I.R.S. Employer Identification No. 77-0212977
50 West San Fernando Street,
San Jose, California 95113
Telephone: (408) 995-5115
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the Registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes [ X ] No [ ]
Indicate the number of shares outstanding of each of the Registrant's classes of
common stock, as of the latest practicable date: $0.001 par value Common Stock
62,894,764 shares outstanding on November 9, 1999.
CALPINE CORPORATION AND SUBSIDIARIES
Report on Form 10-Q
For the Three and Nine months ended September 30, 1999
INDEX
PART I. FINANCIAL INFORMATION Page No.
ITEM 1. Financial Statements
Consolidated Balance Sheets
September 30, 1999 and December 31, 1998..........................3
Consolidated Statements of Operations
Three and Nine months ended September 30, 1999 and 1998...........4
Consolidated Statements of Cash Flows
Nine months ended September 30, 1999 and 1998.....................5
Notes to Consolidated Financial Statements........................6
ITEM 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations.....................13
PART II..OTHER INFORMATION
ITEM 1. Legal Proceedings........................................31
ITEM 2. Change in Securities.....................................32
ITEM 3. Quantitative and Qualitative Disclosures
about Market Risk........................................32
ITEM 4. Submission of Matters to a Vote of Security Holders......32
ITEM 5. Other Information........................................32
ITEM 6. Exhibits and Reports on Form 8-K.........................32
Signatures.................................................................35
2
ITEM 1. FINANCIAL STATEMENTS
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
September 30, 1999 and December 31, 1998
(in thousands)
September 30, December 31,
1999 1998
---------- ----------
(unaudited)
ASSETS
Current assets:
Cash and cash equivalents .......................... $ 173,675 $ 96,532
Accounts receivable ................................ 118,983 79,743
Inventories ........................................ 14,398 14,194
Other current assets ............................... 26,887 19,034
---------- ----------
Total current assets ....................... 333,943 209,503
Property, plant and equipment, net ................... 1,858,233 1,094,303
Investments in power projects ........................ 257,062 221,509
Collateral securities, net of current portion ........ 85,052 86,920
Other assets ......................................... 187,699 116,711
---------- ----------
Total assets ............................... $2,721,989 $1,728,946
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Non-recourse project financing, current portion .... $ -- $ 5,450
Accounts payable ................................... 44,887 53,190
Accrued payroll and related expenses ............... 18,689 9,588
Accrued interest payable ........................... 53,542 25,600
Other current liabilities .......................... 45,861 28,751
---------- ----------
Total current liabilities .................. 162,979 122,579
Construction financing ............................... 115,200 --
Non-recourse project financing, net of current portion -- 114,190
Senior notes ......................................... 1,551,750 951,750
Deferred income taxes, net ........................... 199,937 159,788
Deferred lease incentive ............................. 65,137 67,814
Other liabilities .................................... 44,809 25,859
---------- ----------
Total liabilities .......................... 2,139,812 1,441,980
---------- ----------
Minority interest .................................... 24,128 --
---------- ----------
Stockholders' equity:
Preferred stock, $0.001 par value per share:
authorized 10,000,000 shares, none issued
and outstanding in 1999 and 1998 ................. -- --
Common stock, $0.001 par value per share:
authorized 100,000,000 shares; issued and
outstanding 54,569,788 in 1999 and
40,323,162 in 1998 ............................... 55 40
Additional paid-in capital ......................... 375,595 168,854
Retained earnings .................................. 182,399 118,072
---------- ----------
Total stockholders' equity ................. 558,049 286,966
---------- ----------
Total liabilities and stockholders' equity . $2,721,989 $1,728,946
========== ==========
The accompanying notes are an integral part of these
consolidated financial statements.
3
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF OPERATIONS
For the Three and Nine months ended September 30, 1999 and 1998
(in thousands, except per share amounts)
(unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ ------------------
1999 1998 1999 1998
-------- -------- -------- --------
Revenue:
Electricity and steam sales .......... $225,443 $168,561 $529,765 $347,359
Service contract revenue ............. 21,846 7,835 35,085 16,363
Income from unconsolidated investments
in power projects ................... 15,842 9,778 34,163 16,631
Interest income on loans to
power projects ...................... 517 -- 1,226 2,562
-------- -------- -------- --------
Total revenue .................... 263,648 186,174 600,239 382,915
-------- -------- -------- --------
Cost of revenue:
Plant operating expenses ............. 31,696 20,745 81,480 49,583
Fuel expense ......................... 78,807 62,546 194,265 120,382
Depreciation ......................... 14,005 21,721 56,294 52,532
Production royalties ................. 9,987 4,375 23,539 10,990
Operating lease expenses ............. 4,119 2,791 9,745 8,028
Service contract expenses ............ 21,219 4,926 32,680 11,714
-------- -------- -------- --------
Total cost of revenue ........... 159,833 117,104 398,003 253,229
-------- -------- -------- --------
Gross profit .......................... 103,815 69,070 202,236 129,686
Project development expenses .......... 3,419 1,722 7,667 4,841
General & administrative expenses ..... 13,291 7,389 34,255 18,431
-------- -------- -------- --------
Income from operations ........... 87,105 59,959 160,314 106,414
Other expense (income):
Interest expense ..................... 23,019 24,348 70,190 65,138
Interest income ...................... (6,473) (3,695) (16,305) (9,389)
Minority interest, net ............... 15 -- 15 --
Other income, net .................... (43) 72 (1,278) (834)
-------- -------- -------- --------
Income before provision for
income taxes ......................... 70,587 39,234 107,692 51,499
Provision for income taxes ............ 27,670 15,820 42,215 19,213
-------- -------- -------- --------
Income before extraordinary charge ... 42,917 23,414 65,477 32,286
Extraordinary charge, net of tax
benefit of $--, $233,
$793 and $207 ...................... -- 339 1,150 641
-------- -------- -------- --------
Net income ..................... $ 42,917 $ 23,075 $ 64,327 $ 31,645
======== ======== ======== ========
Basic earnings per common share:
Weighted average shares outstanding .. 54,389 40,274 49,799 40,166
Income before extraordinary charge ... $ 0.79 $ 0.58 $ 1.31 $ 0.80
Extraordinary charge ................. $ -- $ (0.01) $ (0.02) $ (0.01)
Net income ........................... $ 0.79 $ 0.57 $ 1.29 $ 0.79
Diluted earnings per common share:
Weighted average shares outstanding .. 57,990 42,344 52,966 42,182
Income before extraordinary charge ... $ 0.74 $ 0.55 $ 1.24 $ 0.77
Extraordinary charge ................. $ -- $ (0.01) $ (0.03) $ (0.02)
Net income ........................... $ 0.74 $ 0.54 $ 1.21 $ 0.75
The accompanying notes are an integral part of these
consolidated financial statements.
4
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine months ended September 30, 1999 and 1998
(in thousands)
(unaudited)
Nine months ended
September 30,
-----------------------
1999 1998
--------- ---------
Cash flows from operating activities:
Net income ...................................... $ 64,327 $ 31,645
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation and amortization .................. 59,214 53,464
Deferred income taxes, net ..................... 40,481 14,077
Income from unconsolidated investments
in power projects ........................ (34,163) (16,219)
Distributions from unconsolidated power projects 34,178 17,746
Loss on sale of assets ......................... 364 --
Change in operating assets and liabilities:
Accounts receivable .......................... (31,688) (7,085)
Inventories .................................. 602 (4,383)
Other current assets ......................... 584 12,585
Other assets ................................. (10,074) (17,598)
Accounts payable and accrued expenses ........ 44,204 (15,189)
Other liabilities ............................ (1,823) 3,888
Net cash provided by operating activities .. 166,206 72,931
Cash flows from investing activities:
Acquisition of property, plant and equipment .... (668,013) (39,417)
Acquisitions .................................... (175,700) (225,176)
Advances to joint ventures ...................... (14,785) --
Proceeds from sale and leaseback of plant ....... 18,436 --
(Increase)/decrease in notes receivable ......... (5,120) 12,614
Maturities of collateral securities ............. 1,850 6,030
Project development costs ....................... (45,338) (23,288)
Proceeds from restricted cash ................... 7,696 (47)
Net cash used in investing activities ....... (880,974) (269,284)
Cash flows from financing activities:
Borrowings from construction financing .......... 115,200 --
Borrowings from non-recourse project financing .. 128,585 56,424
Repayments of non-recourse project financing .... (248,225) (195,911)
Repayments of notes payable ..................... -- (8,250)
Proceeds from issuance of Senior Notes .......... 600,000 400,000
Proceeds from equity offering ................... 204,585 --
Proceeds from issuance of common stock .......... 2,289 1,053
Write-off of deferred financing costs ........... 1,943 --
Financing costs ................................. (12,466) (4,856)
Net cash provided by financing activities ... 791,911 248,460
Net increase in cash and cash equivalents ......... 77,143 52,107
Cash and cash equivalents, beginning of period .... 96,532 48,513
Cash and cash equivalents, end of period .......... $ 173,675 $ 100,620
Cash paid during the period for:
Interest ........................................ $ 60,982 $ 71,971
Income taxes .................................... $ 5,119 $ 188
The accompanying notes are an integral part of these
consolidated financial statements.
5
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
September 30, 1999
1. Organization and Operation of the Company
Calpine Corporation, a Delaware corporation, and subsidiaries (collectively, the
"Company") is engaged in the development, acquisition, ownership, and operation
of power generation facilities and the sale of electricity and steam principally
in the United States. The Company has ownership interests in and operates
gas-fired cogeneration facilities, geothermal steam fields and geothermal power
generation facilities in northern California, Washington, Texas and various
locations on the East Coast. Each of the generation facilities produces
electricity which is marketed to utilities and other third party purchasers.
Thermal energy produced by the gas-fired cogeneration facilities is primarily
sold to industrial users.
2. Summary of Significant Accounting Policies
Basis of Interim Presentation -- The accompanying interim consolidated financial
statements of the Company have been prepared by the Company, without audit by
independent public accountants, pursuant to the rules and regulations of the
Securities and Exchange Commission. In the opinion of management, the
consolidated financial statements include the adjustments necessary to present
fairly the information required to be set forth therein. Certain information and
note disclosures normally included in financial statements prepared in
accordance with generally accepted accounting principles have been condensed or
omitted from these statements pursuant to such rules and regulations and,
accordingly, should be read in conjunction with the audited consolidated
financial statements of the Company included in the Company's annual report on
Form 10-K for the year ended December 31, 1998. The results for interim periods
are not necessarily indicative of the results for the entire year.
Stock Split -- On September 20, 1999, the Board of Directors authorized a two
for one stock split of the Company's common stock, to be effected in the form of
a stock dividend, payable to stockholders of record as of September 23, 1999.
New shares were distributed on October 7, 1999. All references to number of
shares, except shares authorized, and to per share information in the
consolidated financial statements have been adjusted to reflect the two for one
stock split on a retroactive basis. Par value remains at $.001 per share as a
result of transferring $27,000 to common stock from additional paid-in capital,
representing the aggregate par value of the shares issued under the stock split.
Capitalized interest -- The Company capitalizes interest on projects during the
construction period. For the nine months ended September 30, 1999 and 1998, the
Company capitalized $29.3 million and $6.9 million, respectively, of interest in
connection with the construction of power plants.
Derivative financial instruments -- The Company engages in activities to manage
risks associated with changes in interest rates. The Company has entered into
swap agreements to reduce exposure to interest rate fluctuations in connection
with certain debt commitments. The instruments' cash flows mirror those of the
underlying exposures. Unrealized gains and losses relating to the instruments
are being deferred over the lives of the contracts. The premiums paid on the
instruments, as measured at inception, are being amortized over their respective
lives as components of interest expense. Any gains or losses realized upon the
early termination of these instruments are deferred and recognized in income
over the remaining life of the underlying debt.
New Accounting Pronouncements -- In June 1999, the Financial Accounting
Standards Board issued Statement of Financial Accounting Standards ("SFAS") No.
137, "Accounting for Derivative Instruments and Hedging Activities - Deferral of
the Effective Date of SFAS No. 133". The Statement amends SFAS No. 133 to defer
its effective date to all fiscal quarters of all fiscal years beginning after
June 15, 2000. The Company has not yet analyzed the impact of adopting SFAS No.
133 on the financial statements and has not determined the timing of or method
of the adoption of SFAS No. 133. However, the Statement could increase the
volatility of the Company's earnings.
Reclassifications -- Prior period amounts in the consolidated financial
statements have been reclassified where necessary to conform to the 1999
presentation.
6
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
September 30, 1999
3. Property, Plant and Equipment
Property, plant and equipment consisted of the following (in thousands):
September 30, December 31,
1999 1998
----------- -----------
Geothermal properties ........................ $ 445,091 $ 312,139
Buildings, machinery and equipment ........... 691,437 653,865
Power sales agreements ....................... 145,975 145,957
Gas contracts ................................ 122,543 122,561
Other assets ................................. 65,236 18,955
----------- -----------
1,470,282 1,253,477
Less accumulated depreciation and amortization (280,285) (203,984)
----------- -----------
1,189,997 1,049,493
Land ......................................... 1,625 1,590
Construction in progress ..................... 666,611 43,220
----------- -----------
Property, plant and equipment, net ........... $ 1,858,233 $ 1,094,303
=========== ===========
Construction in progress includes costs primarily attributable to the purchase
of gas-fired turbines for projects currently under development.
4. Results of Unconsolidated Investments in Power Projects
The Company has unconsolidated investments in power projects which are accounted
for under the equity method. Investments in less-than-majority-owned affiliates
and the nature and extent of these investments change over time. The combined
results of operations and financial position of the Company's equity-basis
affiliates are summarized below (in thousands):
Nine Months Ended September 30,
-------------------------------
1999 1998
---------- ----------
Condensed Combined Statements of Operations:
Revenue ................................ $ 363,585 $ 366,412
Net income ............................. $ 84,404 $ 79,378
Company's share of net income .......... $ 34,163 $ 16,631
September 30, December 31,
1999 1998
---------- ----------
Condensed Combined Balance Sheets:
Assets ................................. $1,276,122 $1,274,202
Liabilities ............................ $1,006,793 $1,000,812
The following details the Company's income from investments in unconsolidated
power projects and the service contract revenue recorded by the Company related
to those power projects (in thousands):
Service Contract
Income Revenue
----------------- -----------------
Ownership Nine months ended September 30,
Interest 1999 1998 1999 1998
-------- ----------------- -----------------
Sumas Power Plant (1) ........ -- $20,244 $ 4,052 $ 1,747 $ 2,440
Gordonsville Power Plant ..... 50% 2,814 2,291 -- --
Lockport Power Plant ......... 11.4% 2,821 2,593 -- --
Texas Cogeneration Company ... -- -- 2,922 -- 2,749
Dighton Power Plant .......... 50% 322 -- -- --
Bayonne Power Plant .......... 7.5% 2,741 1,405 -- --
Kennedy International Airport
Power Plant ................. 50% 3,868 2,837 631 --
Sheridan Gas Fields .......... 20% 163 -- -- --
Auburndale Power Plant ....... 5% (38 (956) -- --
Stony Brook Power Plant ...... 50% 1,100 1,119 707 --
Agnews Power Plant ........... 20% (53 (65) 1,769 1,231
Aidlin Power Plant (2) ....... 55% 181 433 1,441 1,382
------- ------- ------- -------
Total .............. $34,163 $16,631 $ 6,295 $ 7,802
======= ======= ======= =======
7
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
September 30, 1999
(1) On December 31, 1998, the Partnership agreement governing Sumas
Cogeneration Company, L.P. ("Sumas") was amended changing the distributions
schedule for the Company from the previously amended agreement dated
September 30, 1997. The newly amended agreement reflects the earnings the
Company was entitled to under that agreement from a variable payment
schedule to a fixed payment schedule. On September 30, 1997, the
partnership agreement was amended changing the distribution percentages to
the partners. As provided for in the amendment, the Company's percentage
share of the project's cash flow increased from 50% to approximately 70%
through June 30, 2001, based on certain specified payments. Thereafter, the
Company will receive 50% of the project's cash flow until a 24.5% pre-tax
rate of return on its original investment is achieved, at which time the
Company's equity interest in the partnership will be reduced to 0.1%. As a
result of the amendment of the partnership agreement and the receipt of
certain distributions during 1997, the Company's investment in Sumas was
reduced to zero. Because the investment has been reduced to zero and there
are no continuing obligations of the Company related to Sumas, the Company
expects that income recorded in future periods will approximate the amount
of cash received from partnership distributions.
(2) The Company acquired an additional 50% interest in the Aidlin Power Plant
on August 31, 1999. As such, the Company has consolidated the operations of
the Aidlin Power Plant.
5. Common Stock and Senior Notes Offering
The following share information reflects the two for one stock split effective
on October 7, 1999. On March 26, 1999, the Company completed a public offering
of 12,000,000 shares of its common stock at $15.50 per share. The net proceeds
from this public offering were approximately $177.9 million. Additionally, in
April 1999, the Company sold an additional 1,800,000 shares of common stock at
$15.50 per share pursuant to the exercise of the underwriters' over-allotment
option for net proceeds of approximately $26.7 million.
On March 29, 1999, the Company completed a public offering of $250.0 million of
its 7-5/8% Senior Notes Due 2006 ("Senior Notes Due 2006") and $350.0 million of
its 7-3/4% Senior Notes Due 2009 ("Senior Notes Due 2009"). The Senior Notes Due
2006 bear interest at 7-5/8% per year, payable semi-annually on April 15 and
October 15 and mature on April 15, 2006. The Senior Notes Due 2006 are not
redeemable prior to maturity. The Senior Notes Due 2009 bear interest at 7-3/4%
per year, payable semi-annually on April 15 and October 15 and mature on April
15, 2009. The Senior Notes Due 2009 are not redeemable prior to maturity. After
deducting underwriting discounts and expenses of the offering, the aggregate net
proceeds from the sale of the Senior Notes were approximately $587.5 million.
The net proceeds from the sale of the common stock, the Senior Notes Due 2006,
and the Senior Notes Due 2009 were used as follows: (i) $120.6 million to
refinance indebtedness relating to the Gilroy Power Plant, (ii) $77.6 million to
repay indebtedness under a bridge facility provided by Credit Suisse First
Boston to finance a portion of the purchase price to acquire the steam fields
that service the Sonoma County power plants, (iii) $50.0 million to repay
outstanding borrowings under our revolving credit facility, (iv) $25.0 million
to complete the expansion of the Clear Lake Power Plant, (v) approximately
$400.0 million to finance a portion of power generation facilities currently
under construction and the projects currently under development, and (vi) the
remaining $118.9 million was used for general corporate purposes. Transaction
costs incurred in connection with the Senior Notes offerings were recorded as a
deferred charge and are amortized over the respective lives of the Senior Notes
Due 2006 and the Senior Notes Due 2009 using the effective interest rate method.
8
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
September 30, 1999
6. Acquisitions
Unocal Transaction
On March 19, 1999, the Company completed the acquisition of Unocal Corporation's
Geysers geothermal steam fields in northern California for approximately $102.1
million. The steam fields fuel the Company's 12 Sonoma County power plants,
totaling 544 megawatts of capacity. The Company purchased these plants from
Pacific Gas & Electric Company ("PG&E") on May 7, 1999.
PG&E Transactions
On May 7, 1999, the Company completed the acquisitions of 12 Sonoma County and 2
Lake County power plants located at The Geysers, California from PG&E. The
approximate purchase price was $212.8 million. The acquisitions were financed
with a 24-year operating lease (see Note 10). The Company's geothermal steam
fields fuel the facilities, which have a combined capacity of approximately 700
megawatts of electricity. All of the electricity generated from the facilities
is sold into the California energy market, with the exception of megawatts sold
under an agreement entered into on April 29, 1999 with Commonwealth Energy
Corporation as follows: 75 megawatts in 1999, 100 megawatts in 2000, and 125
megawatts in 2001 and through June 2002.
7. Construction Financing
On January 4, 1999, the Company entered into a Credit Agreement with ING (U.S.)
Capital LLC ("ING") to provide up to $265.0 million of non-recourse project
financing for the construction of the Pasadena facility expansion. As of
September 30, 1999, $115.2 million was outstanding as a construction loan under
the agreement. The outstanding loan bears interest at ING's base rate plus an
applicable margin or at LIBOR plus an applicable margin and is payable
quarterly. The construction loan will convert to a term loan once the project
has completed construction. The construction loan will mature on or before July
1, 2000, but is subject to an extension to October 1, 2000 if there are
sufficient construction funds available. The term loan will be available for a
period not to exceed five years from the construction loan maturity date. In
connection with the Credit Agreement, the Company entered into a $10.0 million
letter of credit facility. At September 30, 1999, there were no letters of
credit outstanding under the facility.
8. Revolving Credit Facility and Line of Credit
The Company maintains a credit facility of $100.0 million, which is available
through a consortium of commercial lending institutions led by The Bank of Nova
Scotia as agent. A maximum of $50.0 million of the credit facility may be
allocated to letters of credit. At September 30, 1999, the Company had no
borrowings and $26.0 million of letters of credit outstanding under the credit
facility. Borrowings bear interest at The Bank of Nova Scotia's base rate plus
an applicable margin or at LIBOR plus an applicable margin. Interest is paid on
the last day of each interest period for such loans. The credit facility
specifies that the Company maintain certain covenants, with which the Company
was in compliance as of September 30, 1999. Commitment fees related to this
credit facility are charged based on 0.375% of committed unused funds.
The Company had a $12.0 million letter of credit outstanding with The Bank of
Nova Scotia to secure performance of the Clear Lake Power Plant.
9
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
September 30, 1999
9. Earnings per Share
All share information reflects the two for one stock split effective on October
7, 1999.
Periods Ended September 30, 1999 1998
---------------------------- ----------------------------
Weighted Weighted
Net Average Net Average
(in thousands, except per share amounts) Income Shares EPS Income Shares EPS
------------------------------------------------------------------------------------------------------
Three Months:
Basic earnings per common share:
Income before extraordinary charge .... $ 42,917 26,923 $ 0.79 $ 23,414 40,274 $ 0.58
Extraordinary charge net of tax benefit
of $-- and $207 ...................... -- -- 339 (0.01)
-------- ------ -------- ------
Basic earnings per common share ....... $ 42,917 26,923 $ 0.79 $ 23,075 40,274 $ 0.57
======== ====== ====== ======== ====== ======
Common shares issuable upon
Exercise of stock options using
Treasury stock method ............... 3,601 2,070
------ ------
Diluted earnings per common share:
Income before extraordinary charge .... $ 42,917 57,990 $ 0.74 $ 23,414 42,344 $ 0.55
Extraordinary charge net of tax benefit
of $-- and $207 ...................... -- -- 339 (0.01)
-------- ----- -------- ------
Diluted earnings per share ............ $ 42,917 57,990 $ 0.74 $ 23,075 42,344 $ 0.54
======== ====== ===== ======== ====== ======
Nine Months:
Basic earnings per common share:
Income before extraordinary charge .... $ 65,477 49,799 $ 1.31 $ 32,286 40,166 $ 0.80
Extraordinary charge net of tax benefit
of $793 and $441 ..................... 1,150 (0.02) 641 (0.01)
-------- ----- -------- ------
Basic earnings per share .............. $ 64,327 49,799 $ 1.29 $ 31,645 40,166 $ 0.79
======== ====== ===== ======== ====== ======
Common shares issuable upon
Exercise of stock options using
Treasury stock method ............... 3,167 2,016
------ ------
Diluted earnings per common share:
Income before extraordinary charge .... $ 65,477 52,966 $ 1.24 $ 32,286 42,182 $ 0.77
Extraordinary charge net of tax benefit
of $793 and $441 ..................... 1,150 (0.03) 641 (0.02)
-------- ----- -------- ------
Diluted earnings per share ............ $ 64,327 52,966 $ 1.21 $ 31,645 42,182 $ 0.75
======== ====== ===== ======== ====== ======
The Company recognized an extraordinary charge of $1.2 million or $0.03 per
share (net of tax benefit of $793,000) in April of 1999, representing the
write-off of deferred financing costs related to non-recourse project financing
for the Gilroy Power Plant. The financing agreement was terminated and the
outstanding balance of $120.6 million was repaid in April of 1999. For the three
months ended September 30, 1998, the Company recognized an extraordinary charge
of $339,000 or $0.01 per share (net of tax benefit of $207,000) as a result of
the repurchase of $4.3 million of the 10-1/2% Senior Notes Due 2006. For the
nine months ended September 30, 1998, the Company has recognized an
extraordinary charge of $641,000 or $0.01 per share (net of tax benefit of
$441,000) for the repurchase of $8.3 million of the 10-1/2 % Senior Notes Due
2006. The notes were redeemed at a premium plus accrued interest to the date of
repurchase.
Unexercised employee stock options to purchase 720,800 and 98,000 shares of the
Company's common stock during the nine months ended September 30, 1999 and 1998,
respectively, were not included in the computation of diluted shares outstanding
because such inclusion would be anti-dilutive.
10. Commitments and Contingencies
Production Royalties and Leases -- The Company is committed under several
geothermal leases and right-of-way, easement and surface agreements. The
geothermal leases generally provide for royalties based on production revenue
with reductions for property taxes paid. The right-of-way, easement and surface
agreements are based on flat rates and are not material. Certain properties also
have net profits and overriding royalty interests ranging from approximately
1.45% to 28%, which are in addition to the land
10
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
September 30, 1999
royalties. Most lease agreements contain clauses providing for minimum lease
payments to lessors if production temporarily ceases or if production falls
below a specified level.
The Company leases its corporate offices and regional offices in San Jose,
California, Boston, Massachusetts, Houston, Texas and Pleasanton, California,
under noncancellable operating leases expiring through 2002. Future minimum
lease payments under these leases for the remainder of 1999 are approximately
$500,000.
Facilities Operating and Land Leases - The Company entered into long-term
operating leases in June 1995, May 1996, August 1998 and May 1999 for its
Watsonville, King City, Greenleaf, Sonoma and Lake County power plants and the
land lease for the Pasadena Power Plant. Future minimum lease payments under
these leases for the remainder of 1999 are approximately $10.6 million.
In May 1999, the Company entered into a sale and leaseback transaction for
certain plant and equipment located at The Geysers, California for a net book
value of $231.8 million. Included in the transaction were the 12 Sonoma County
and 2 Lake County power plants purchased from PG&E on May 7, 1999 (see Note 6),
as well as the Sonoma Power Plant acquired from the Sacramento Municipal Utility
District in 1998. Under the terms of the agreement, the Company received $18.5
million and recorded a deferred gain of $15.2 million on the balance sheet. The
deferred gain is being amortized over the term of the lease through May 2022.
Natural Gas Purchases -- The Company enters into short-term and long-term gas
purchase contracts with third parties to supply natural gas to its gas-fired
projects.
Capital expenditures -- At September 30, 1999, the Company was under contract
with Siemens Westinghouse Power Corporation for a total of $1.8 billion for the
purchase of 50 turbines. Approximate payments related to these turbines for the
nine months ended September 30, 1999 was $487.4 million.
Litigation
On September 30, 1997, a lawsuit was filed by Indeck North American Power Fund
("Indeck") in the Circuit Court of Cook County, Illinois against Norweb plc. and
certain other parties, including the Company. Some of Indeck's claims relate to
Calpine Gordonsville, Inc.'s acquisition of a 50% interest in Gordonsville
Energy L.P. from Northern Hydro Limited and Calpine Auburndale, Inc.'s
acquisition of a 50% interest in Auburndale Power Plant Partners Limited
Partnership from Norweb Power Services (No. 1) Limited. Indeck claimed that
Calpine Gordonsville, Inc., Calpine Auburndale, Inc. and the Company tortuously
interfered with Indeck's contractual rights to purchase such interests and
conspired with other parties to do so. Indeck is seeking $25.0 million in
compensatory damages, $25.0 million in punitive damages, and the recovery of
attorneys' fees and costs. In April 1999, the court granted Calpine Gordonsville
and Calpine Auburndale's motions to dismiss with prejudice, a decision which has
been appealed by Indeck. The Company is unable to predict the outcome of these
proceedings.
An action was filed against Lockport Energy Associates, L.P. and the New York
Public Service Commission ("NYPSC") in August 1997 by New York State Electricity
and Gas Company ("NYSEG") in the Federal District Court for the Northern
District of New York. NYSEG has requested the Court to direct NYPSC and the
Federal Energy Regulatory Commission ("FERC") to modify contract rates to be
paid to the Lockport Power Plant. In October 1997, NYPSC filed a cross-claim
alleging that the FERC violated the Public Utility Regulatory Policies Act of
1978 as amended, ("PURPA") and the Federal Power Act by failing to reform the
NYSEG contract that was previously approved by the NYPSC. Although it is unable
to predict the outcome of this case, in any event, the Company retains the right
to require The Brooklyn Union Gas Company to purchase the Company's interest in
the Lockport Power Plant for $18.9 million, less equity distributions received
by the Company, at any time before December 19, 2001.
The Company is involved in various other claims and legal actions arising out of
the normal course of business. The Company does not expect that the outcome of
these proceedings will have a material adverse
11
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
September 30, 1999
effect on the Company's financial position or results of operations, although no
assurance can be given in this regard.
11. Subsequent Events
On October 1, 1999, the Company completed the acquisition of Sheridan Energy
Inc. ("Sheridan Energy"), a natural gas exploration and production company,
through a $41.0 million cash tender offer. The Company purchased the outstanding
shares of Sheridan Energy's common stock for $5.50 per share and assumed $64.5
million of outstanding debt. In addition, the Company redeemed $11.5 million of
outstanding preferred stock of Sheridan Energy. Sheridan Energy's oil and gas
properties, including 148 billion cubic feet equivalent of proven reserves, are
located in Northern California and the Gulf Coast region. On January 4, 1999,
the Company acquired a 20% interest in Sheridan California Energy, Inc. from
Sheridan Energy. As a result of the two aforementioned acquisitions, the Company
now owns all of the assets of Sheridan Energy.
On November 2, 1999, the Company completed a public offering of 7,200,000 shares
of its common stock at $46.31 per share. The net proceeds from this public
offering were approximately $320.3 million. The Company sold an additional
1,080,000 shares of common stock at $46.31 per share pursuant to the exercise of
the underwriters' over-allotment option for net proceeds of approximately $48.2
million.
Concurrently with the public offering dated November 2, 1999, the Company,
through its subsidiary Calpine Capital Trust, a statutory business trust created
under Delaware law, completed an offering of 4,800,000 Remarketable Term Income
Deferrable Equity Securities ("trust preferred securities") at a value of $50.00
per share. The net proceeds from the offering were approximately $233.2 million.
The Company sold an additional 720,000 trust preferred securities at a value of
$50.00 per share pursuant to the exercise of the underwriters' over-allotment
option for net proceeds of approximately $35.0 million. The net proceeds from
the offering were used by the Company's subsidiary to invest in convertible
subordinated debentures of the Company, which represent substantially all of the
subsidiary's assets. The Company has guaranteed all of the subsidiary's
obligations under the trust preferred securities. The trust preferred securities
will be reflected on the balance sheet as "Company-obligated mandatorily
redeemable convertible preferred securities of a subsidiary trust", while
distributions will be reflected in the statements of operations as a minority
interest captioned as "Distributions on trust preferred securities". The trust
preferred securities accrue distributions at a rate of 5-3/4% per annum, have a
liquidation value of $50.00 per share, are convertible into shares of the
Company's common stock at a rate of 0.8565 shares of common stock for each trust
preferred security, and may be redeemed at any time on or after November 5, 2002
at a redemption price equal to 101.44% of the principal amount plus any accrued
and unpaid interest declining to 100% of the principal amount on or after
November 5, 2003. Additionally, the Company has the right to defer the interest
payments on the debentures for up to twenty consecutive quarters, which would
also cause a deferral of distributions on the trust preferred securities.
Currently, the Company has no intention of deferring interest payments on the
debentures.
On November 3, 1999, the Company entered into a $1.0 billion revolving
construction credit facility with Credit Suisse First Boston, New York branch
and The Bank of Nova Scotia, as lead arrangers. The non-recourse credit facility
will be utilized to finance the construction of its diversified portfolio of
gas-fired power plants currently under development. The Company currently
intends to refinance this construction facility in the long-term capital markets
prior to its four-year maturity.
12
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
Except for historical financial information contained herein, the matters
discussed in this quarterly report may be considered forward-looking statements
within the meaning of Section 27A of the Securities Act of 1933, as amended, and
Section 21E of the Securities Exchange Act of 1934, as amended and subject to
the safe harbor created by the Securities Litigation Reform Act of 1995. Such
statements include declarations regarding our intent, belief or current
expectations. Prospective investors are cautioned that any such forward-looking
statements are not guarantees of future performance and involve a number of
risks and uncertainties; actual results could differ materially from those
indicated by such forward-looking statements. Among the important factors that
could cause actual results to differ materially from those indicated by such
forward-looking statements are: (i) that the information is of a preliminary
nature and may be subject to further adjustment, (ii) the possible
unavailability of financing, (iii) risks related to the development,
acquisition, and operation of power plants, (iv) the impact of avoided cost
pricing, energy price fluctuations and gas price increases, (v) the impact of
curtailment, (vi) the seasonal nature of our business, (vii) start-up risks,
(viii) general operating risks, (ix) the dependence on third parties, (x) risks
associated with international investments, (xi) risks associated with the power
marketing business, (xii) changes in government regulation, (xiii) the
availability of natural gas, (xiv) the effects of competition, (xv) the
dependence on senior management, (xvi) volatility in our stock price, (xvii)
fluctuations in quarterly results and seasonality, and (xviii) other risks
identified from time to time in our reports and registration statements filed
with the Securities and Exchange Commission.
Management Overview
Calpine is engaged in the development, acquisition, ownership, and operation of
power generation facilities and the sale of electricity and steam principally in
the United States. At October 27, 1999, we had interests in 38 power plants and
steam fields predominantly in the United States, having an aggregate capacity of
3,694 megawatts.
On January 4, 1999, we completed the acquisition of a 20% interest in 82 billion
cubic feet of proven natural gas reserves located in the Sacramento basin of
Northern California. We paid approximately $14.9 million for $13.0 million in
redeemable non-voting preferred stock and 20% of the outstanding common stock of
Sheridan California Energy, Inc ("SCEI"). Additionally, we signed a ten year gas
contract enabling us to purchase 100% of SCEI's production.
On February 17, 1999, we announced that the Delta Energy Center met the
California Energy Commission's Data Adequacy requirements. This ruling stated
that our Application for Certification contained adequate information for the
California Energy Commission to begin its analysis of the power plant's
environmental impacts and proposed mitigation. The Delta Energy Center, an 880
megawatt gas-fired power plant located at the Dow Chemical facility in
Pittsburg, California, is the first power plant that will be developed, owned
and operated under a joint venture with Bechtel Enterprises, and will provide
power to the Pittsburg, California and greater San Francisco Bay Area. The
gas-fired power plant is to be constructed by Bechtel and operated by us.
On February 17, 1999, we announced plans to develop, own and operate a 545
megawatt gas-fired power plant in Westbrook, Maine. We acquired the development
rights for the Westbrook Power Plant from Genesis Power Corporation. This power
plant is scheduled to begin power deliveries by the end of 2000, and will serve
the New England market.
On February 24, 1999, we announced plans to develop, own and operate a 600
megawatt gas-fired power plant located in San Jose, California. This power
plant, called the Metcalf Energy Center, is the second power plant to be
developed under the joint venture with Bechtel Enterprises, and will provide
electricity to the San Francisco Bay area. We plan to commence operation in mid
2002.
On March 19, 1999, we completed the acquisition of Unocal Corporation's Geysers
geothermal steam fields in northern California for approximately $102.1 million.
The steam fields fuel our 12 Sonoma County
13
power plants, totaling 544 megawatts of capacity. We purchased these plants from
Pacific Gas and Electric Company ("PG&E") on May 7, 1999 (see Note 6 to the
Notes to Consolidated Financial Statements).
On April 14, 1999, we received approval from the California Energy Commission to
construct a 545 megawatt gas-fired power plant near Yuba City, California. This
power plant, called the Sutter Power Plant, was the first new power plant
approved in California's deregulated power industry. Electricity produced by the
Sutter Power Plant will be sold into California's energy market. We expect the
plant to commence operation in early 2001.
On April 22, 1999, we entered into a joint venture with GenTex Power Corporation
to develop, own and operate a 545 megawatt gas-fired power plant in Bastrop
County, Texas, called Lost Pines I. Construction of this power plant is expected
to begin in October 1999. We will manage all phases of the plant's development
process, with GenTex and ourselves jointly operating the plant. The output from
Lost Pines I will be divided equally, with GenTex selling its portion to its
customer base, while we will sell our portion to the wholesale power market in
Texas. We expect the plant to commence operation in mid 2001.
On April 23, 1999, we entered into a joint agreement with Pinnacle West Capital
Corporation to develop, own and operate a 545 megawatt gas-fired power plant
located in Phoenix, Arizona. This plant, called the West Phoenix Power Plant,
will provide power to the Phoenix metropolitan area, and construction will
commence in 2000. We expect the plant to commence operation in 2002.
On May 7, 1999, we completed the acquisitions of 12 Sonoma County and 2 Lake
County power plants from PG&E. The approximate purchase price was $212.8
million. The acquisitions were financed with a 24 year operating lease. Our
geothermal steam fields fuel the facilities, which have a combined capacity of
approximately 694 megawatts of electricity. All of the generation from the
facilities is sold to the California energy market, with the exceptionof
megawatts sold under an agreement entered into on April 29, 1999, with
Commonwealth Energy Corporation as follows: 75 megawatts in 1999, 100 megawatts
in 2000, and 125 megawatts in 2001 and through June 2002. Historically, we have
served as a steam supplier for these facilities, which had been owned and
operated by PG&E. These acquisitions have enabled us to consolidate our
operations in The Geysers and to integrate the power plant and steam field
operations, allowing us to optimize the efficiency and performance of the
facilities. We believe that these acquisitions provide us with significant
synergies that leverage our expertise in geothermal power generation and
position us to benefit from the demand for "green" energy in the competitive
market.
On June 21, 1999, we acquired the rights to build, own and operate a 545
megawatt gas-fired power plant located in Ontelaunee Township, Pennsylvania. The
plant, called the Ontelaunee Energy Center, will provide power to residences and
businesses throughout the Pennsylvania-New Jersey-Maryland power pool.
Construction will commence in 2000 and the plant is scheduled to begin
production in 2002.
On August 20, 1999, we announced the purchase of 18 F-class combustion turbines
from Siemens Westinghouse Power Corporation that will be capable of producing
4,900 megawatts of electricity in a combined-cycle configuration. Beginning in
2002, Siemens will deliver six turbines per year through 2004. Combined with our
existing turbine order we now have 69 turbines under contract, option or letter
of intent capable of producing 17,745 megawatts.
On August 27, 1999, we announced an agreement with Cogeneration Corporation of
America ("CGCA") to acquire 80% of its common stock for $25.00 per share or
approximately $145.0 million. NRG Energy, Inc., a wholly owned subsidiary of
Northern States Power, will own the remaining 20%. The transaction is subject to
the approval of CGCA shareholders and we expect to consummate the acquisition by
year end 1999. CGCA currently owns interests in six natural gas-fired power
plants, totaling 579 megawatts. The plants are located in Pennsylvania, New
Jersey, Illinois and Oklahoma.
On August 31, 1999, we completed the acquisition of an additional 50% of the
Aidlin Power Plant from Edison Mission Energy (5%) and General Electric Capital
Corporation (45%) for a total purchase price of $7.2 million. We now own 55% of
the 20 megawatt Aidlin Power Plant.
14
On September 20, 1999, the Board of Directors authorized a two for one stock
split of our common stock, to be effected in the form of a stock dividend,
payable to stockholders of record on September 23, 1999. New shares were
distributed on October 7, 1999. In the Management's Discussion and Analysis, all
references to the number of common shares and per share amounts have been split
adjusted.
On September 29, 1999, we completed the acquisition of development rights to
build, own and operate the Los Medanos Power Plant from Enron North America. The
Los Medanos Power Plant is a 550 megawatt gas-fired cogeneration plant located
adjacent to USS-POSCO Industries' steel mill in Pittsburg, California. Los
Medanos will supply USS-POSCO with 60 megawatts of electricity and 75,000 pounds
per hour of steam, and market the excess electricity into the California power
exchange and under bilateral contracts. Construction commenced in September 1999
and commercial operation is scheduled to occur in 2001.
On September 30, 1999, we announced plans to build, own and operate an 800
megawatt gas-fired cogeneration power plant at Bayer Corporation's chemical
facility in Baytown, Texas. The Baytown Power Plant will supply Bayer with all
of its electric and steam requirements for 20 years and market excess
electricity into the Texas wholesale power market. Construction is estimated to
commence in 2000 and commercial operation in 2001.
Transactions Announced or Consummated Subsequent to September 30, 1999
On October 1, 1999, we completed the acquisition of Sheridan Energy, Inc., a
natural gas exploration and production company, through a $41.0 million cash
tender offer. We purchased the outstanding shares of Sheridan Energy's common
stock for $5.50 per share. In addition, we redeemed $11.5 million of outstanding
preferred stock of Sheridan Energy. Sheridan Energy's oil and gas properties,
including 148 billion cubic feet equivalent of proven reserves, are located in
northern California and the Gulf Coast region, where we are developing low-cost
natural gas supplies and proprietary pipeline systems to support our
strategically-located natural gas-fired power plants.
On October 21, 1999, we completed the acquisition of the Calistoga geothermal
power plant from FPL Energy and Caithness Corporation for approximately $78.0
million. The acquisition was financed with a 23-year operating lease. Located in
The Geysers region of northern California, Calistoga is a 67 megawatt facility
which provides electricity to PG&E under a long-term contract.
On October 25, 1999, we announced that we had executed a letter of intent which
gives us the exclusive right to negotiate with LYONDELL-CITGO Refining L.P. to
build, own and operate a 560 megawatt gas-fired cogeneration power plant at the
LYONDELL-CITGO refinery in Houston, Texas. The Channel Energy Center will supply
all of the electricity and steam requirements for 20 years to the refinery.
Permitting for the facility is currently underway, with construction projected
to commence in early 2000 and commercial operation in 2001.
On November 2, 1999, we completed a public offering of 7,200,000 shares of our
common stock at $46.31 per share. The net proceeds from this public offering
were approximately $320.3 million. We sold an additional 1,080,000 shares of
common stock at $46.31 per share pursuant to the exercise of the underwriters'
over-allotment option for net proceeds of approximately $48.2 million.
Concurrent with the public offering dated November 2, 1999, Calpine, through its
subsidiary Calpine Capital Trust, a statutory business trust created under
Delaware law, completed an offering of 4,800,000 Remarketable Term Income
Deferrable Equity Securities ("trust preferred securities") at a value of $50.00
per share. The net proceeds from the offering were approximately $233.2 million.
We sold an additional 720,000 trust preferred securities at a value of $50.00
per share pursuant to the exercise of the underwriters' over-allotment option
for net proceeds of approximately $35.0 million. The net proceeds from the
offering were used by our subsidiary to invest in our convertible subordinated
debentures, which represent substantially all of the subsidiary's assets. We
have guaranteed all of the subsidiary's obligations under the trust preferred
securities. The trust preferred securities will be reflected on the balance
sheet as "Company-obligated mandatorily redeemable convertible preferred
securities of a subsidiary trust", while distributions will be reflected in the
statements of operations as a minority interest captioned as "Distributions on
trust preferred securities". The trust preferred securities accrue distributions
at a rate of 5-3/4% per annum, have a
15
liquidation value of $50.00 per share, are convertible into shares of the our
common stock at a rate of 0.8565 shares of common stock for each trust preferred
security, and may be redeemed at any time on or after November 5, 2002 at a
redemption price equal to 101.44% of the principal amount plus any accrued and
unpaid interest declining to 100% of the principal amount on or after November
5, 2003. We have the right to defer the interest payments on the debentures for
up to twenty consecutive quarters, which would also cause a deferral of
distributions on the trust preferred securities.
On November 3, 1999, we completed the acquisition of development rights to
build, own and operate the Towantic Energy Center from Arena Capital Ltd. The
Towantic Energy Center is a 500 megawatt gas-fired cogeneration plant located in
Oxford, Connecticut. The Towantic Energy Center will market its electricity via
bilateral contracts into the New England region. Construction is estimated to
commence in 2000 and commercial operation in 2002.
On November 3, 1999, we entered into a $1.0 billion revolving construction
credit facility with Credit Suisse First Boston, New York branch and The Bank of
Nova Scotia, as lead arrangers. The non-recourse credit facility will be
utilized to finance the construction of our diversified portfolio of gas-fired
power plants currently under development. We currently intend to refinance the
construction facility in the long-term capital markets prior to its four-year
maturity.
Selected Operating Information
Set forth below is certain selected operating information for the power plants
and steam fields, for which results are consolidated in our statements of
operations. The information set forth under Power Plants consists of the results
for the West Ford Flat Power Plant, Bear Canyon Power Plant, Greenleaf 1 & 2
Power Plants, Watsonville Power Plant, King City Power Plant, Gilroy Power
Plant, the Bethpage Power Plant since its acquisition on February 5, 1998, the
Texas City and Clear Lake Power Plants since their acquisition on March 31,
1998, the Pasadena Power Plant since it began commercial operation on July 7,
1998, the Sonoma Power Plant since its acquisition on July 17, 1998, the
Pittsburg Power Plant since its acquisition on July 21, 1998, the 12 Sonoma
County and 2 Lake County power plants purchased from PG&E on May 7, 1999, and
the acquisition of an additional 50% interest in the Aidlin Power Plant on
August 31, 1999. The information set forth under Steam Fields consists of the
results for the Thermal Power Company Steam Fields prior to the acquisition.
(in thousands, except Three Months Ended Nine months ended
price per kilowatt hour) September 30, September 30,
------------------------ -------------------------
1999 1998 1999 1998
Power Plants: ----------- ----------- ----------- -----------
Electricity revenues:
Energy .............. $ 169,518 $ 89,150 $ 346,835 $ 182,885
Capacity (1) ........ $ 55,925 $ 67,361 $ 162,080 $ 134,464
Megawatt hours produced 4,736,851 2,665,399 10,758,267 4,995,089
Average energy price
per kilowatt hour .. $ 0.03579 $ 0.03345 $ 0.03224 $ 0.03661
Steam Fields:
Steam Revenue: ........ $ -- $ 12,050 $ 20,850 $ 30,010
Megawatt hours produced -- 658,766 1,192,722 1,637,402
Average price per
Kilowatt hour ...... $ -- $ 0.01829 $ 0.01748 $ 0.01833
(1) Capacity revenues include, besides traditional capacity payments, other
revenues such as Reliability Must Run and Ancillary Service revenues.
Megawatt hours produced at the power plants increased 42% and 80% for the three
and nine months ended September 30, 1999 as compared with the same periods in
1998. The three month increase was primarily due to additional megawatt hours
produced at the 14 geothermal power plants purchased from PG&E on May 7, 1999.
The increase for the nine months ended September 30, 1999 includes the effect of
the geothermal plants acquired from PG&E, as well as the start up of the
Pasadena Power Plant, and the
16
acquisitions of the Texas City, Clear Lake, Pittsburg and Bethpage Power Plants
in 1998.
Due to the consolidation of the power plants purchased from PG&E on May 7, 1999,
the revenue previously recognized for the Steam Fields will now be incorporated
in our Power Plants revenue.
OTHER FINANCIAL DATA AND RATIOS
Set forth below are certain other financial data and ratios for the periods
indicated (in thousands, except ratio data):
Three Months Ended Nine Months Ended
September 30, September 30,
------------------- -------------------
1999 1998 1999 1998
-------- -------- -------- --------
Depreciation and amortization .. $ 13,786 $ 33,749 $ 56,443 $ 65,852
Interest expense per indenture . $ 26,615 $ 25,976 $ 78,649 $ 69,187
EBITDA ......................... $119,103 $ 93,434 $268,239 $187,016
EBITDA to interest expense
per indenture ............... $ 4.48x $ 3.60x $ 3.41x $ 2.70x
EBITDA is defined as income from operations plus depreciation, capitalized
interest, other income, non-cash charges and cash received from investments in
power projects, reduced by the income from unconsolidated investments in power
projects. EBITDA is presented not as a measure of operating results, but rather
as a measure of our ability to service debt. EBITDA should not be construed as
an alternative either (i) to income from operations (determined in accordance
with generally accepted accounting principles) or (ii) to cash flows from
operating activities (determined in accordance with generally accepted
accounting principles).
Interest expense per indenture is defined as total interest expense plus
one-third of all operating lease obligations, dividends paid in respect to
preferred stock and cash contributions to any employee stock ownership plan used
to pay interest on loans to purchase capital stock of the company.
Results of Operations
Three and nine months ended September 30, 1999 Compared to three and nine months
ended September 30, 1998 Consolidated Operations.
(Dollars in thousands)
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------ ------------------------
% %
Revenue: 1999 1998 Change 1999 1998 Change
-------- -------- ------ -------- -------- ------
Electricity and steam sales $225,443 $168,561 34% $529,765 $347,359 53%
Service contract revenue ... 21,846 7,835 179% 35,085 16,363 114%
Income from unconsolidated
investments in power
projects .................. 15,842 9,778 62% 34,163 16,631 105%
Interest on loans to power
projects .................. 517 -- 100% 1,226 2,562 -52%
-------- -------- ------ -------- -------- ------
Total revenue ......... $263,648 $186,174 42% $600,239 $382,915 57%
======== ======== ====== ======== ======== ======
Revenue -- Total revenue increased 42% and 57% to $263.6 million and $600.2
million for the three months and nine months ended September 30, 1999 compared
to $186.2 million and $382.9 million in 1998.
Electricity and steam sales revenue increased 34% to $225.4 million for the
three months ended September 30, 1999 compared to $168.6 million in the same
period in 1998. The increase is primarily attributable to the consolidation of
our Geysers operation in Northern California during the first half of calendar
1999, which increased electricity revenues by $71.9 million. The Pasadena Power
Plant, which became operational in July 1998, contributed $22.1 million in
additional revenue during 1999. These increases were partially offset by a
decrease of $9.6 million at the Bear Canyon and West Ford Flat Power Plants
relating to the expiration of the fixed priced period of their power sales
agreements. Consequently,
17
the price of electricity for these two power plants was significantly reduced
compared to the price for the same period in 1998. Furthermore, there was a
$12.0 million reduction in steam revenues related to the consolidation of the
PG&E power plants acquired on May 7, 1999. For the nine months ended September
30, 1999, electricity and steam revenues increased 53% to $529.8 million as
compared to $347.4 million for the same period a year ago. These increases are
primarily due an increase of $171.2 million for power plants that were acquired
during 1998 and 1999, and $40.5 million for our Pasadena Plant that became
operational in the third quarter of 1998, partially offset by a decrease of
$31.5 million at the Bear Canyon and West Ford Flat Power Plants relating to the
expiration of the fixed priced period of their power sales agreements.
Service contract revenue increased to $21.8 million and $35.1 million for the
three and nine months ended September 30, 1999 compared to $7.8 million and
$16.4 million for the same periods in 1998. The increase was primarily
attributable to a reclass made to record year to date third party gas sales as
revenue rather than netted against gas purchases.
Income from unconsolidated investments in power projects increased 62% to $15.8
million for the three months ended September 30, 1999 compared to $9.8 million
for the same period in 1998. The increase is primarily attributable to an
increase of $4.8 million of equity income from our investment in Sumas, and $1.0
million of additional equity income from our investments in the Auburndale and
Gordonsville Power Plants. For the nine months ended September 30, 1999, income
from unconsolidated investments in power projects increased 105% to $34.2
million as compared to $16.6 million for the same period a year ago. This
increase is primarily attributable to an increase of $16.2 million of equity
income from our investment in Sumas, and increase of $1.3 million of equity
income from our investment in the Bayonne Power Plant, and increase of $1.4
million of equity income from our investments in the Auburndale and Gordonsville
Power Plants, and an increase of $1.0 million of equity income from our
investment in the Kennedy International Airport Power Plant. These increases
were partially offset by a reduction of $2.9 million in equity income from our
Texas City and Clear Lake Power Plants, which were consolidated on March 31,
1998 (see Note 4 to the Notes to Consolidated Financial Statements).
Interest income on loans to power projects was $517,000 for the three
months ended September 30, 1999 and is attributable to dividend income received
from Sheridan California Energy, Inc. We will no longer receive dividend income
from SCEI due to the acquisition and consolidation of Sheridan Energy on October
1, 1999. For the nine months ended September 30, 1999, interest income on loans
to power projects decreased to $1.2 million compared to $2.6 million for the
same period a year ago. The decrease is primarily related to the acquisition of
the remaining 50% interest in Texas Cogeneration Company on March 31, 1998,
offset by dividend income received from SCEI.
Cost of revenue -- Cost of revenue increased to $159.8 million and $398.0
million for the three and nine months ended September 30, 1999 compared to
$117.1 million and $253.2 million for the same periods in 1998. The increases of
$42.7 million and $144.8 million were primarily attributable to increased plant
operating, and fuel expenses as a result of the acquisition of the remaining
interests in the Texas City and Clear Lake Power Plants on March 31, 1998, the
acquisition of the remaining interest in the Bethpage Power Plant on February 5,
1998, the acquisition of the Pittsburg Power Plant on July 21, 1998, the
consolidation of our Geysers operations on May 7, 1999, and the startup of the
Pasadena Power Plant in July of 1998.
General and administrative expenses -- General and administrative expenses
increased to $13.3 million for the three months ended September 30, 1999
compared to $7.4 million in 1998. For the nine months ended September 30, 1999,
general and administrative expenses increased to $34.3 million compared to $18.4
million for the same period in 1998. The increases were attributable to
continued growth in personnel, compensation and associated overhead costs
necessary to support the overall growth in our operations.
Interest expense -- Interest expense decreased 6% to $23.0 million for the three
months ended September 30, 1999 from $24.3 million for the same period in 1998.
The decrease was primarily attributable to an increase in capitalized interest
of $15.3 million in connection with the construction of power plants as compared
to the same period in 1998, partially offset by $11.7 million of interest
associated with the issuance of senior notes in 1999. For the nine months ended
September 30, 1999, interest expense
18
increased to $70.2 million from $65.1 million for the same period a year ago.
The increase was primarily attributable to $33.5 million of interest associated
with the issuances of senior notes in 1999 and 1998, partially offset by an
increase in capitalized interest of $22.4 million, and a decrease in interest
expense of $5.2 million related to the retirement of non-recourse project
financing for the Greenleaf Power Plant in 1998 and the Gilroy Power Plant in
1999.
Provision for income taxes -- The effective income tax rate was approximately
39% for the three and nine months ended September 30, 1999. The reductions from
the statutory tax rate were primarily due to depletion in excess of tax basis
benefits at our geothermal facilities, and a decrease in the average state tax
rate due to our expansion into states other than California.
Liquidity and Capital Resources
To date, we have obtained cash from our operations, borrowings under our credit
facilities and other working capital lines, sale of debt and equity, and
proceeds from non-recourse project financing. We utilized this cash to fund our
operations, service debt obligations, fund acquisitions, develop and construct
power generation facilities, finance capital expenditures and meet our other
cash and liquidity needs. The following table summarizes our cash flow
activities for the periods indicated:
Nine Months Ended September 30,
-------------------------------
1999 1998
--------- ---------
Cash flows from: (in thousands)
Operating activities ................... $ 166,206 $ 72,931
Investing activities ................... (880,974) (269,284)
Financing activities ................... 791,911 248,460
--------- ---------
Total .......................... $ 77,143 $ 52,107
========= =========
Operating activities for 1999 provided $166.2 million, consisting of
approximately $64.2 million of net income, $59.2 million of depreciation and
amortization, $34.2 million of distributions from unconsolidated investments in
power projects, $40.5 million of deferred income taxes, a $42.4 million net
increase in operating liabilities, and a loss on sale of assets of $364,000.
This was offset by $40.6 million net increase in operating assets and $34.2
million of income from unconsolidated investments.
Investing activities for 1999 used $881.0 million, primarily due to $102.2
million for the acquisition of steam fields from Unocal, $50.9 million for the
acquisition of Sheridan Energy Inc., $7.2 million for the acquisition of an
additional 50% interest in the Aidlin Power Plant, $14.9 million for the
acquisition of a 20% interest in Sheridan California Energy Inc., advances to
the Lost Pines I Joint Venture of $14.8 million, $112.6 million of capital
expenditures related to the construction of the Pasadena Power Plant Expansion,
$555.4 million of other capital expenditures principally for turbine purchases
and for the Clear Lake Expansion project, $16.0 million of capitalized project
development costs, $29.3 million of interest capitalized on construction
projects, $8.2 million of additional loans to principal owners of power plants,
$655,000 for the acquisition of additional investments, offset by $1.9 million
in maturities of collateral securities in connection with the King City Power
Plant, the repayment of $3.1 million of outstanding loans, a $7.7 million
decrease in restricted cash, and $18.4 million from the sale and leaseback
transaction of the Geysers Power Company plants.
Financing activities for 1999 provided $791.9 million of cash consisting of
$115.2 million of borrowings for the construction of the Pasadena Power Plant,
$77.6 million of borrowings related to a bridge facility, $51.0 million in
borrowings of non-recourse project financing, $792.1 million of net proceeds
from additional equity and senior debt financings received in March and April of
1999, $2.3 million for the issuance of common stock for our Employee Stock
Purchase Plan, and $1.9 million for the write off of deferred financing costs in
April 1999, partially offset by $170.6 million in repayment of non-recourse
project financing in April 1999, and $77.6 million of repayments related to a
bridge facility.
19
At September 30, 1999, cash and cash equivalents were $173.7 million and
working capital was $171.0 million. For 1999, cash and cash equivalents
increased by $77.1 million and working capital increased by $84.0 million as
compared to December 31, 1998.
As a developer, owner and operator of power generation facilities, we are
required to make long-term commitments and investments of substantial capital
for our projects. We historically have financed these capital requirements with
cash from operations, borrowings under our credit facilities, other lines of
credit, construction financing, non-recourse project financing or long-term
debt, and the sale of equity.
We continue to evaluate current and forecasted cash flow as a basis for
financing operating requirements and capital expenditures. We believe that we
will have sufficient liquidity from cash flow from operations, borrowings
available under the lines of credit and working capital to satisfy all
obligations under outstanding indebtedness, to finance anticipated capital
expenditures and to fund working capital requirements for the next twelve
months.
On January 4, 1999, the Company entered into a Credit Agreement with ING to
provide up to $265.0 million of non-recourse project financing for the
construction of the Pasadena Power Plant expansion. As of September 30, 1999,
$115.2 million was outstanding as a construction loan under the agreement. The
outstanding loan bears interest at ING's base rate plus an applicable margin or
at LIBOR plus an applicable margin and is payable quarterly. The construction
loan will convert to a term loan once the project has completed construction.
The construction loan will mature on or before July 1, 2000, but is subject to
an extension to October 1, 2000 if there are sufficient construction funds
available. The term loan will be available for a period not to exceed five years
from the construction loan maturity date. In connection with the Credit
Agreement, the Company entered into a $10.0 million letter of credit facility.
At September 30, 1999, there were no letters of credit outstanding under the
facility.
On March 26, 1999, we completed a public offering of 12,000,000 shares of
our common stock at $15.50 per share. All share information reflects the two for
one stock split effective on October 7, 1999. The net proceeds from this public
offering were approximately $177.9 million. Additionally, in April 1999, we sold
an additional 1,800,000 shares of common stock at $15.50 per share pursuant to
the exercise of the underwriters' over-allotment option for net proceeds of
approximately $26.7 million.
On March 29, 1999, we completed a public offering of $250.0 million of our
7-5/8% Senior Notes Due 2006 and of our $350.0 million 7-3/4% Senior Notes Due
2009. After deducting underwriting discounts and expenses of the offering, the
aggregate net proceeds from the sale of the Senior Notes were approximately
$587.5 million. The Senior Notes Due 2006 bear interest at 7-5/8% per year,
payable semi-annually on April 15 and October 15 each year and mature on April
15, 2006. The Senior Notes Due 2006 are not redeemable prior to maturity. The
Senior Notes Due 2009 bear interest at 7-3/4% per year, payable semi-annually on
April 15 and October 15 each year and mature on April 15, 2009. The Senior Notes
Due 2009 are not redeemable prior to maturity.
The net proceeds from the sale of the common stock, the Senior Notes Due
2006, and the Senior Notes Due 2009 were used as follows: (i) $120.6 million to
refinance indebtedness relating to the Gilroy Power Plant, (ii) $77.6 million to
repay indebtedness under a bridge facility provided by Credit Suisse First
Boston to finance a portion of the purchase price to acquire the steam fields
that service the Sonoma County power plants, (iii) $50.0 million to repay
outstanding borrowings under our revolving credit facility, (iv) $25.0 million
to complete the expansion of the Clear Lake Power Plant, (v) approximately
$400.0 million to finance a portion of power generation facilities currently
under construction and the projects currently under development, and (vi) the
remaining $118.9 million will be used for general corporate purposes.
Transaction costs incurred in connection with the Senior Notes offering were
recorded as a deferred charge and are amortized over the respective lives of the
Senior Notes Due 2006 and the Senior Notes Due 2009 using the effective interest
rate method.
At September 30, 1999, we also had $105.0 million of outstanding 9-1/4%
Senior Notes Due 2004, which mature on February 1, 2004, with interest payable
semi-annually on February 1 and August 1 of each year. In addition, we had
$171.8 million of outstanding 10-1/2% Senior Notes Due 2006, which mature on
20
May 15, 2006, with interest payable semi-annually on May 15 and November 15 of
each year. During 1997, we issued $275.0 million of 8-3/4% Senior Notes Due
2007, which mature on July 15, 2007, with interest payable semi-annually on
January 15 and July 15 of each year. During 1998, we issued $400.0 million of
7-7/8% Senior Notes Due 2008, which mature on April 1, 2008, with interest
payable semi-annually on April 1 and October 1 of each year.
At September 30, 1999, we had a $100.0 million revolving credit facility
available with a consortium of commercial lending institutions. We had no
borrowings and $26.0 million of letters of credit outstanding under the credit
facility (See Note 8 to the Notes to Consolidated Financial Statements). The
credit facility contains certain restrictions that limit or prohibit, among
other things, our ability to incur indebtedness, make payments of certain
indebtedness, pay dividends, make investments, engage in transactions with
affiliates, create liens, sell assets and engage in mergers and consolidations.
At September 30, 1999, we had a $12.0 million letter of credit outstanding
with The Bank of Nova Scotia to secure performance of the Clear Lake Power
Plant.
Outlook
Our strategy is to continue our rapid growth by capitalizing on the
significant opportunities in the power industry, primarily through our active
development and acquisition programs. In pursuing our proven growth strategy, we
utilize our extensive management and technical expertise to implement a fully
integrated approach to the acquisition, development and operation of power
generation facilities. This approach uses our expertise in design, engineering,
procurement, finance, construction management, fuel and resource acquisition,
operations and power marketing, which we believe provide us with a competitive
advantage. The key elements of our strategy are as follows:
* Development and expansion of power plants. We are actively pursuing the
development and expansion of highly efficient, low-cost, gas-fired power
plants that replace old and inefficient generating facilities and meet the
demand for new generation. Our strategy is to develop power plants in
strategic geographic locations that enable us to leverage existing power
generation assets and operate the power plants as integrated electric
generation systems. This allows us to achieve significant operating
synergies and efficiencies in fuel procurement, power marketing and
operations and maintenance.
We currently have nine new projects under construction, representing an
additional 4,485 megawatts of capacity. Of these new projects, we are
expanding our Pasadena facility by 545 megawatts to 785 megawatts and we
have eight new power plants under construction, including the Tiverton
Power Plant in Rhode Island; the Rumford Power Plant in Maine; the
Westbrook Power Plant in Maine; the Sutter Power Plant in California; the
Los Medanos Power Plant in California; the South Point Power Plant in
Arizona; the Magic Valley Power Plant in Texas; and the Lost Pines I Power
Plant in Texas. We have also announced plans to develop six additional
power generation facilities, totaling 4,430 megawatts, in California,
Connecticut, Texas, Arizona and Pennsylvania.
* Acquisition of power plants. Our strategy is to acquire power generating
facilities that meet our stringent acquisition criteria and provide
significant potential for revenue, cash flow and earnings growth, and that
provide the opportunity to enhance the operating efficiencies of the
plants. We have significantly expanded and diversified our project
portfolio through the acquisition of power generation facilities through
the completion of 32 acquisitions to date.
* Enhance the performance and efficiency of existing power projects. We
continually seek to maximize the power generation potential of our
operating assets and minimize our operating and maintenance expenses and
fuel costs. This will become even more significant as our portfolio of
power generation facilities expands to an aggregate of 52 power plants with
an aggregate capacity of approximately 8,758 megawatts, after completion of
our pending acquisitions and projects currently under construction. We
focus on operating our plants as an integrated system of power generation,
which enables us to minimize costs and maximize operating efficiencies. We
believe that achieving
21
and maintaining a low-cost of production will be increasingly important to
compete effectively in the power generation industry.
Risk Factors
We have substantial indebtedness that we may be unable to service and that
restricts our activities. We have substantial debt that we incurred to finance
the acquisition and development of power generation facilities. As of September
30, 1999 our total consolidated indebtedness was $1.7 billion, our total
consolidated assets were $2.7 billion and our stockholders' equity was $558.0
million. Whether we will be able to meet our debt service obligations and to
repay our outstanding indebtedness will be dependent primarily upon the
performance of our subsidiaries.
This high level of indebtedness has important consequences, including:
* limiting our ability to borrow additional amounts for working capital,
capital expenditures, debt service requirements, execution of our growth
strategy, or other purposes,
* limiting our ability to use operating cash flow in other areas of our
business because we must dedicate a substantial portion of these funds to
service the debt,
* increasing our vulnerability to general adverse economic and industry
conditions, and
* limiting our ability to capitalize on business opportunities and to react
to competitive pressures and adverse changes in government regulation.
The operating and financial restrictions and covenants in our existing debt
agreements, including the indentures relating to our $1.6 billion aggregate
principle amount of senior notes and our $100.0 million revolving credit
facility, contain restrictive covenants. Among other things these restrictions
limit or prohibit our ability to:
* incur indebtedness,
* make prepayments of indebtedness in whole or in part,
* pay dividends,
* make investments,
* engage in transactions with affiliates,
* create liens,
* sell assets, and
* acquire facilities or other businesses.
Also, if our management or ownership changes, our indentures governing our
senior notes may require us to make an offer to purchase our senior notes. We
cannot assure you that we will have the financial resources necessary to
purchase our senior notes in this event.
We believe that our cash flow from operations, together with other
available sources of funds, including borrowings under our existing borrowing
arrangements, will be adequate to pay principal and interest on our debt and to
enable us to comply with the terms of our debt agreements. If we are unable to
comply with the terms of our debt agreements and fail to generate sufficient
cash flow from operations in the future, we may be required to refinance all or
a portion of our senior notes and other debt or to obtain additional financing.
However, we may be unable to refinance or obtain additional financing because of
our high levels of debt and the debt incurrence restrictions under our debt
agreements. If cash flow is insufficient and refinancing or additional financing
is unavailable, we may be forced to default on our senior notes and other debt
obligations. In the event of a default under the terms of any of our
indebtedness, the debt holders may accelerate the maturity of our obligations,
which could cause defaults under our other obligations.
Our ability to repay our debt depends upon the performance of our
subsidiaries. Almost all of our operations are conducted through our
subsidiaries and other affiliates. As a result, we depend almost entirely upon
their earnings and cash flow to service our indebtedness, including our ability
to pay the interest on and principal of our senior notes. Non-recourse project
financing agreements generally restrict
22
our ability to pay dividends, make distributions or otherwise transfer funds to
us prior to the payment of other obligations, including operating expenses, debt
service and reserves.
Our subsidiaries and other affiliates are separate and distinct legal
entities and have no obligation to pay any amounts due on our senior notes, and
do not guarantee the payment of interest on or principal of these notes. The
right of our senior note holders to receive any assets of any of our
subsidiaries or other affiliates upon our liquidation or reorganization will be
subordinated to the claims of any subsidiaries' or other affiliates' creditors
(including trade creditors and holders of debt issued by our subsidiaries or
affiliates). As of September 30, 1999, our subsidiaries had $115.2 million of
construction financing. We intend to utilize non-recourse project and
construction financing in the future that will be effectively senior to our
senior notes.
While the indentures impose limitations on our ability and the ability of
our subsidiaries to incur additional indebtedness, the indentures do not limit
the amount of non-recourse project financing that our subsidiaries may incur to
finance new power generation facilities.
We may be unable to secure additional financing in the future. Each power
generation facility that we acquire or develop will require substantial capital
investment. Our ability to arrange financing and the cost of the financing are
dependent upon numerous factors. These factors include:
* general economic and capital market conditions,
* conditions in energy markets,
* regulatory developments,
* credit availability from banks or other lenders,
* investor confidence in the industry and in us,
* the continued success of our current power generation facilities, and
* provisions of tax and securities laws that are conducive to raising
capital.
Financing for new facilities may not be available to us on acceptable terms
in the future. We have financed our existing power generation facilities using a
variety of sources, primarily consisting of non-recourse project financing,
lease obligations, and from the proceeds of our senior debt and equity
issuances. As of September 30, 1999, we had approximately $1.7 billion of total
consolidated indebtedness, $115.2 million of which represented construction
financing. Each construction financing, non-recourse project financing and lease
obligation is structured to be fully paid out of cash flow provided by the
facility or facilities. In the event of a default under a financing agreement
which we do not cure, the lenders or lessors would generally have rights to the
facility and any related assets. In the event of foreclosure after a default, we
might not retain any interest in the facility. While we intend to utilize
non-recourse or lease financing when appropriate, market conditions and other
factors may prevent similar financing for future facilities. We do not believe
the existence of non-recourse or lease financing will significantly affect our
ability to continue to borrow funds in the future in order to finance new
facilities. However, it is possible that we may be unable to obtain the
financing required to develop our power generation facilities on terms
satisfactory to us.
We have from time to time guaranteed certain obligations of our
subsidiaries and other affiliates. Our lenders or lessors may also require us to
guarantee the indebtedness for future facilities. This would render our general
corporate funds vulnerable in the event of a default by the facility or related
subsidiary. Additionally, our indentures may restrict our ability to guarantee
future debt, which could adversely affect our ability to fund new facilities.
Our indentures do not limit the ability of our subsidiaries to incur
non-recourse or lease financing for investment in new facilities.
Revenue under some of our power sales agreements may be reduced
significantly upon their expiration or termination. Most of the electricity we
generate from our existing portfolio is sold under long-term power sales
agreements that expire at various times. When the terms of each of these power
sales agreements expire, it is possible that the price paid to us for the
generation of electricity may be reduced significantly, which would
substantially reduce our revenue under such agreements. The fixed price periods
in some of our long-term power sales agreements have recently expired, and the
electricity under
23
those agreements is now sold at a fluctuating market price. For example, the
price for electricity for two of our power plants, the Bear Canyon (20
megawatts) and the West Ford Flat (27 megawatts) power plants, was approximately
13.83 cents per kilowatt hour under the fixed price periods that recently
expired for these facilities, and is now set at the energy clearing price, which
averaged 2.61 cents per kilowatt hour for the nine months ended September 30,
1999. As a result, our energy revenue under these power sales agreements has
been materially reduced. We expect the decline in energy revenues will be
partially mitigated by decreased royalties and planned operating cost reductions
at these facilities. In addition, we will continue our strategy of offsetting
these reductions through our acquisition and development program.
Our power project development and acquisition activities may not be
successful. The development of power generation facilities is subject to
substantial risks. In connection with the development of a power generation
facility, we must generally obtain:
* necessary power generation equipment,
* governmental permits and approvals,
* fuel supply and transportation agreements,
* sufficient equity capital and debt financing,
* electrical transmission agreements, and
* site agreements and construction contracts.
We may be unsuccessful in accomplishing any of these matters or in doing so
on a timely basis. In addition, project development is subject to various
environmental, engineering and construction risks relating to cost-overruns,
delays and performance. Although we may attempt to minimize the financial risks
in the development of a project by securing a favorable power sales agreement,
obtaining all required governmental permits and approvals and arranging adequate
financing prior to the commencement of construction, the development of a power
project may require us to expend significant amounts for preliminary
engineering, permitting and legal and other expenses before we can determine
whether a project is feasible, economically attractive or financeable. If we
were unable to complete the development of a facility, we would generally not be
able to recover our investment in the project. The process for obtaining initial
environmental, siting and other governmental permits and approvals is
complicated and lengthy, often taking more than one year, and is subject to
significant uncertainties. We cannot assure you that we will be successful in
the development of power generation facilities in the future.
We have grown substantially in recent years as a result of acquisitions of
interests in power generation facilities and steam fields. We believe that
although the domestic power industry is undergoing consolidation and that
significant acquisition opportunities are available, we are likely to confront
significant competition for acquisition opportunities. In addition, we may be
unable to continue to identify attractive acquisition opportunities at favorable
prices or, to the extent that any opportunities are identified, we may be unable
to complete the acquisitions.
Our projects under construction may not commence operation as scheduled.
The commencement of operation of a newly constructed power generation facility
involves many risks, including:
* start-up problems,
* the breakdown or failure of equipment or processes, and
* performance below expected levels of output or efficiency.
New plants have no operating history and may employ recently developed and
technologically complex equipment. Insurance is maintained to protect against
certain risks, warranties are generally obtained for limited periods relating to
the construction of each project and its equipment in varying degrees, and
contractors and equipment suppliers are obligated to meet certain performance
levels. The insurance, warranties or performance guarantees, however, may not be
adequate to cover lost revenues or increased expenses. As a result, a project
may be unable to fund principal and interest payments under its financing
obligations and may operate at a loss. A default under such a financing
obligation could result in losing our interest in a power generation facility.
24
In addition, power sales agreements entered into with a utility early in
the development phase of a project may enable the utility to terminate the
agreement, or to retain security posted as liquidated damages, if a project
fails to achieve commercial operation or certain operating levels by specified
dates or if we fail to make specified payments. In the event a termination right
is exercised, the default provisions in a financing agreement may be triggered
(rendering such debt immediately due and payable). As a result, the project may
be rendered insolvent and we may lose our interest in the project.
Our power generation facilities may not operate as planned. Upon completion
of our pending acquisitions and projects currently under construction, we will
operate 42 of the 52 power plants in which we will have an interest. The
continued operation of power generation facilities involves many risks,
including the breakdown or failure of power generation equipment, transmission
lines, pipelines or other equipment or processes and performance below expected
levels of output or efficiency. Although from time to time our power generation
facilities have experienced equipment breakdowns or failures, these breakdowns
or failures have not had a significant effect on the operation of the facilities
or on our results of operations. For the nine months ended September 30, 1999,
our gas-fired power generation facilities have operated at an average
availability of approximately 93% and our geothermal power generation facilities
have operated at an average availability of approximately 97%. Although our
facilities contain various redundancies and back-up mechanisms, a breakdown or
failure may prevent the facility from performing under applicable power sales
agreements. In addition, although insurance is maintained to protect against
operating risks, the proceeds of insurance may not be adequate to cover lost
revenues or increased expenses. As a result, we could be unable to service
principal and interest payments under our financing obligations which could
result in losing our interest in the power generation facility.
Our geothermal energy reserves may be inadequate for our operations. The
development and operation of geothermal energy resources are subject to
substantial risks and uncertainties similar to those experienced in the
development of oil and gas resources. The successful exploitation of a
geothermal energy resource ultimately depends upon:
* the heat content of the extractable fluids,
* the geology of the reservoir,
* the total amount of recoverable reserves,
* operating expenses relating to the extraction of fluids,
* price levels relating to the extraction of fluids, and
* capital expenditure requirements relating primarily to the drilling of new
wells.
In connection with each geothermal power plant, we estimate the
productivity of the geothermal resource and the expected decline in
productivity. The productivity of a geothermal resource may decline more than
anticipated, resulting in insufficient reserves being available for sustained
generation of the electrical power capacity desired. An incorrect estimate by us
or and unexpected decline in productivity could lower our results of operations.
Geothermal reservoirs are highly complex. As a result, there exist numerous
uncertainities in determining the extent of the reservoirs and the quantity and
productivity of the steam reserves. Reservoir engineering is an inexact process
of estimating underground accumulations of steam or fluids that cannot be
measured in any precise way, and depends significantly on the quantity and
accuracy of available data. As a result, the estimates of other reservoir
specialists may differ materially from ours. Estimates of reserves are generally
revised over time on the basis of the results of drilling, testing and
production that occur after the original estimate was prepared. While we have
extensive experience in the operation and development of geothermal energy
resources and in preparing such estimates, we cannot assure you that we will be
able to successfully manage the development and operation of our geothermal
reservoirs or that we will accurately estimate the quantity or productivity of
our steam reserves.
We depend on our electricity and thermal energy customers. Each of our
power generation facilities currently relies on one or more power sales
agreements with one or more utility or other customers for all or substantially
all of such facility's revenue. In addition, the sales of electricity to two
utility customers during the first nine months of 1999 comprised approximately
47% of our total revenue during that period.
25
The loss of any one power sales agreement with any of these customers could have
a negative effect on our results of operations. In addition, any material
failure by any customer to fulfill its obligations under a power sales agreement
could have a negative effect on the cash flow available to us and our results of
operations.
We are subject to complex government regulation which could adversely
affect our operations. Our activities are subject to complex and stringent
energy, environmental and other governmental laws and regulations. The
construction and operation of power generation facilities require numerous
permits, approvals and certificates from appropriate federal, state and local
governmental agencies, as well as compliance with environmental protection
legislation and other regulations. While we believe that we have obtained the
requisite approvals for our existing operations and that our business is
operated in accordance with applicable laws, we remain subject to a varied and
complex body of laws and regulations that both public officials and private
individuals may seek to enforce. Existing laws and regulations may be revised or
new laws and regulations may become applicable to us that may have a negative
effect on our business and results of operations. We may be unable to obtain all
necessary licenses, permits, approvals and certificates for proposed projects,
and completed facilities may not comply with all applicable permit conditions,
statutes or regulations. In addition, regulatory compliance for the construction
of new facilities is a costly and time-consuming process. Intricate and changing
environmental and other regulatory requirements may necessitate substantial
expenditures to obtain permits. If a project is unable to function as planned
due to changing requirements or local opposition, it may create expensive delays
or significant loss of value in a project.
Our operations are potentially subject to the provisions of various energy
laws and regulations, including the Public Utility Regulatory Policies Act of
1978, as amended ("PURPA"), the Public Utility Holding Company Act of 1955, as
amended ("PUHCA"), and state and local regulations. PUHCA provides for the
extensive regulation of public utility holding companies and their subsidiaries.
PURPA provides to qualifying facilities ("QFs") (as defined under PURPA) and
owners of QFs certain exemptions from certain federal and state regulations,
including rate and financial regulations.
Under present federal law, we are not subject to regulation as a holding
company under PUHCA, and will not be subject to such regulation as long as the
plants in which we have an interest (1) qualify as QFs, (2) are subject to
another exemption or waiver or (3) qualify as exempt wholesale generators
("EWG") under the Energy Policy Act of 1992. In order to be a QF, a facility
must be not more than 50% owned by an electric utility company or electric
utility holding company. In addition, a QF that is a cogeneration facility, such
as the plants in which we currently have interests, must produce electricity as
well as thermal energy for use in an industrial or commercial process in
specified minimum proportions. The QF also must meet certain minimum energy
efficiency standards. Any geothermal power facility which produces up to 80
megawatts of electricity and meets PURPA ownership requirements is considered a
QF.
If any of the plants in which we have an interest lose their QF status or
if amendments to PURPA are enacted that substantially reduce the benefits
currently afforded QFs, we could become a public utility holding company, which
could subject us to significant federal, state and local regulation, including
rate regulation. If we become a holding company, which could be deemed to occur
prospectively or retroactively to the date that any of our plants loses its QF
status, all our other power plants could lose QF status because, under FICC
regulations, a QF cannot be owned by an electric utility or electric utility
holding company. In addition, a loss of QF status could, depending on the
particular power purchase agreement, allow the power purchaser to cease taking
and paying for electricity or to seek refunds of past amounts paid and thus
could cause the loss of some or all contract revenues or otherwise impair the
value of a project. If a power purchaser were to cease taking and paying for
electricity or seek to obtain refunds of past amounts paid, there can be no
assurance that the costs incurred in connection with the project could be
recovered through sales to other purchasers. Such events could adversely affect
our ability to service our indebtedness, including our senior notes.
Currently, Congress is considering proposed legislation that would amend
PURPA by eliminating the requirement that utilities purchase electricity from
QFs at prices based on avoided costs of energy. We do
26
not know whether this legislation will be passed or, if passed, what form it may
take. We cannot assure that any legislation passed would not adversely impact
our existing domestic projects.
In addition, many states are implementing or considering regulatory
initiatives designed to increase competition in the domestic power generation
industry and increase access to electric utilities' transmission and
distribution systems for independent power producers and electricity consumers.
In particular, the state of California has restructured its electric industry by
providing for a phased-in competitive power generation industry, with a power
pool and an independent system operator, and for direct access to generation for
all power purchasers outside the power exchange under certain circumstances.
Although existing QF power sales contracts are to be honored under such
restructuring, and all of our California operating projects are QFs, until the
new system is fully implemented, it is impossible to predict what impact, if
any, it may have on the operations of those projects.
We may be unable to obtain an adequate supply of natural gas in the future.
To date, our fuel acquisition strategy has included various combinations of our
own gas reserves, gas prepayment contracts and short-, medium- and long-term
supply contracts. In our gas supply arrangements, we attempt to match the fuel
cost with the fuel component included in the facility's power sales agreements,
in order to minimize a project's exposure to fuel price risk. We believe that
there will be adequate supplies of natural gas available at reasonable prices
for each of our facilities when current gas supply agreements expire. However,
gas supplies may not be available for the full term of the facilities' power
sales agreements, and gas prices may increase significantly. If gas is not
available, or if gas prices increase above the fuel component of the facilities'
power sales agreements, there could be a negative impact on our results of
operations.
Competition could adversely affect our performance. The power generation
industry is characterized by intense competition. We encounter competition from
utilities, industrial companies and other power producers. In recent years,
there has been increasing competition in an effort to obtain power sales
agreements. This competition has contributed to a reduction in electricity
prices. In addition, many states have implemented or are considering regulatory
initiatives designed to increase competition in the domestic power industry.
This competition has put pressure on electric utilities to lower their costs,
including the cost of purchased electricity.
Our international investments may face uncertainties. We have one
investment in geothermal steam fields located in Mexico and may pursue
additional international investments. International investments are subject to
unique risks and uncertainties relating to the political, social and economic
structures of the countries in which we invest. Risks specifically related to
investments in non-United States projects may include:
* risks of fluctuations in currency valuation,
* currency inconvertibility,
* expropriation and confiscatory taxation,
* increased regulation, and
* approval requirements and governmental policies limiting returns to foreign
investors.
We depend on our senior management. Our success is largely dependent on the
skills, experience and efforts of our senior management. The loss of the
services of one or more members of our senior management could have a negative
effect on our business, financial results and future growth.
Seismic disturbances could damage our project. Areas where we operate and
are developing many of our geothermal and gas-fired projects are subject to
frequent low-level seismic disturbances. More significant seismic disturbances
are possible. Our existing power generation facilities are built to withstand
relatively significant levels of seismic disturbances, and we believe we
maintain adequate insurance protection. However, earthquake, property damage or
business interruption insurance may be inadequate to cover all potential losses
sustained in the event of serious seismic disturbances. Additionally, insurance
may not continue to be available to us on commercially reasonable terms.
27
Our results are subject to quarterly and seasonal fluctuations. Our
quarterly operating results have fluctuated in the past and may continue to do
so in the future as a result of a number of factors, including:
* the timing and size of acquisitions,
* the completion of development projects, and
* variations in levels of production.
Additionally, because we receive the majority of capacity payments under
some of our power sales agreements during the months of May through October, our
revenues and results of operations are, to some extent, seasonal.
The price of our common stock is volatile. The market price for our common
stock has been volatile in the past, and several factors could cause the price
to fluctuate substantially in the future. These factors include:
* announcements of developments related to our business,
* fluctuations in our results of operations,
* sales of substantial amounts of our securities into the marketplace,
* general conditions in our industry or the worldwide economy,
* an outbreak of war or hostilities,
* a shortfall in revenues or earnings compared to securities analysts'
expectations,
* changes in analysts' recommendations or projections, and
* announcements of new acquisitions or development projects by us.
The market price of our common stock may fluctuate significantly in the
future, and these fluctuations may be unrelated to our performance. General
market price declines or market volatility in the future could adversely affect
the price of our common stock, and thus, the current market price may not be
indicative of future market prices.
We could be adversely affected if our computer systems are not Year 2000
compliant. The "Year 2000 problem" refers to the fact that some computer
hardware, software and embedded systems were designed to read and store dates
using only the last two digits of the year.
We are coordinating our efforts to address the impact of Year 2000 on our
business through a Year 2000 Project Team comprised of representatives from each
business unit and our Year 2000 project office. The Year 2000 project office is
charged with addressing additional Year 2000 related issues including, but not
limited to, business continuation and other contingency planning. The Year 2000
Project Team meets regularly to monitor the efforts of assigned staff and
contractors to identify, remediate and test our technology.
The Year 2000 Project Team is focusing on four separate technology domains:
* Corporate applications, which include core business systems;
* Non-Information technology, which includes all operating and control
systems;
* End-User computing systems (that is, systems that are not, considered core
business systems but may contain date calculations); and
* Business partner and vendor systems.
Corporate Applications - Corporate applications are those major core
systems, such as customer information, human resources and general ledger, for
which our Management Information Systems department has the responsibility. We
utilize PeopleSoft for our major core systems. The PeopleSoft applications are
in operation and have been determined to be Year 2000 compliant.
Non-Information Technology/Embedded Systems - Non-information technology
includes such items as power plant operating and control systems,
telecommunications and facilities-based equipment and other embedded systems.
Each business unit is responsible for the inventory and remediation of its
embedded
28
systems. In addition, we are working with the Electric Power Research Institute,
a consortium of power companies, including investor-owned utilities, to
coordinate vendor contacts and product evaluation. Because many embedded systems
are similar across utilities, this concentrated effort should help to reduce
total time expended in this area and help to ensure that the Company's efforts
are consistent with the efforts and practices of other power companies and
utilities.
An Inventory phase for non-information technology/embedded systems was
completed in October 1998. The Initial Assessment Phase was completed in
December 1998. We plan to complete remediation of non-compliant systems by the
fourth quarter of 1999. To date, all embedded systems that have been identified
by Calpine can be upgraded or modified within our current schedule. The schedule
for addressing year 2000 issues with respect to mission critical embedded
systems is as follows:
PHASE STATUS ESTIMATED COMPLETION DATE
- -------------------- ---------------- -------------------------
Inventory Complete September 1998
Initial Assessment Complete November 1998
Detail Assessment Complete May 1999
Remediation Complete November 1999
Contingency Planning In-progress(90%) November 1999
Testing of embedded systems is complex because some of the testing must be
completed during power plant scheduled maintenance outages. Most of the testing
is already completed in cooperation with vendors and other power companies.
Remainder of the testing is scheduled this year during regularly scheduled
maintenance outage periods. So far we have not found anything during the testing
and remediation which we think will hinder us from achieving our Year 2000
objective.
End-User Computing Systems - Some of our business units have developed
systems, databases, spreadsheets, etc. that contain date calculations.
Compliance of individual workstations is also included in this domain. These
systems comprise a relatively small percentage of the required modification in
terms of both number and criticality.
Our end-user computing systems are being inventoried by each business unit
and evaluated and remediated by the Company's MIS staff. We expect to complete
this process by year-end 1999.
Business Partner and Vendor Systems - We have contracts with business
partners and vendors who provide products and services to the Company. We are
vigorously seeking to obtain Year 2000 assurances from these third parties. Year
2000 Project Team and appropriate business units are jointly undertaking this
effort. We have sent letters and accompanying Year 2000 surveys to about 800
vendors and suppliers. We have received most of responses as of Sept 1999. These
responses outline to varying degrees the approach vendors are undertaking to
resolve Year 2000 issues within their own systems. Majority of our vendors and
suppliers have indicated that they are ready for year 2000 or they are making
significant progress and will be ready by the year-end. Follow-up letters are
being sent to all vendors to ascertain their latest status.
Contingency Planning - Contingency and business continuation planning are
in various stages of development for critical and high-priority systems. Our
existing disaster response plan and other contingency plans are scheduled to be
evaluated and will be adopted for use in case of any Year 2000related
disruption. We expect to complete our contingency planning by November 1999.
Costs - The costs of expected modifications are currently estimated to be
approximately $1.7 million which will be charged to expense as incurred. For the
nine months ended September 30, 1999, $401,000 has been charged to expense.
Approximately 9% of the estimated total cost has been incurred in 1998, 63% will
be incurred in 1999, and the remainder will be incurred in 2000. These costs
have been and will be funded through operating cash flow. These estimates may
change as additional evaluations are completed and remediation and testing
progress.
29
Risks - We currently expect to complete our Year 2000 efforts with respect
to critical systems by fall of 1999. This schedule and our cost estimates may be
affected by, among other things, the availability of Year 2000 personnel, the
readiness of third parties, the timing for testing our embedded systems, the
availability of vendor resources to complete embedded system assessments and
produce required component upgrades and our ability to implement appropriate
contingency plans.
We produce revenues by selling power we produce to customers. We depend on
transmission and distribution facilities that are owned and operated by
investor-owned utilities to deliver power to the our customers. If either our
customers or the providers of transmission and distribution facilities
experience significant disruptions as a result of the Year 2000 problem, our
ability to sell and deliver power may be hindered, which could result in a loss
of revenue.
The cost or consequences of a materially incomplete or untimely resolution
of the Year 2000 problem could adversely affect our future operations, financial
results or our financial condition.
Financial Market Risks
From time to time, we use interest rate swap agreements to mitigate our
exposure to interest rate fluctuations. We do not use derivative financial
instruments for speculative or trading purposes. The following table summarizes
the fair market value of our existing interest rate swap agreements as of
September 30, 1999 (in thousands):
Weighted
Average
Notional Interest Fair
Maturity Date Principal Amount Rate Market Value
- -------------- ---------------- ---------- -------------
2000 $ 17,150 9.9% $ (371)
2009 65,000 6.1% 2,253
2013 75,000 7.2% (2,307)
2014 79,970 6.7% 410
- -------------- ---------------- ---------- -------------
Total $237,120 7.1% $ (15)
================ ========== =============
Short-term investments. As of September 30, 1999, we have short-term
investments of $45.7 million. These short-term investments consist of highly
liquid investments with maturities between three and twelve months. These
investments are subject to interest rate risk and will increase in value if
market interest rates increase. We have the ability to hold these investments to
maturity, and as a result, we would not expect the value of these investments to
be affected to any significant degree by the effect of a sudden change in market
interest rates. Declines in interest rates over time will reduce our interest
income.
Outstanding debt. As of September 30, 1999, we have outstanding long-term
debt of approximately $1.7 billion primarily made up of $1.6 billion of senior
notes and $115.2 million of construction financing. Our construction financing
has a floating interest rate of 6.75% as of September 30, 1999. Our outstanding
long-term Senior Notes as of September 30, 1999 are as follows (in thousands):
Carrying Fair
Maturity Date Amount Interest Rate Market Value
------------- ----------- ------------- ------------
2004 $ 105,000 9-1/4% $ 106,050
2006 171,750 10-1/2% 182,270
2006 250,000 7-5/8% 238,438
2007 275,000 8-3/4% 272,594
2008 400,000 7-7/8% 384,600
2009 350,000 7-3/4% 318,938
------------- ----------- ------------
Total $ 1,551,750 $ 1,502,890
=========== ============
Gas price fluctuations. We enter into derivative commodity instruments to
hedge our exposure to the impact of price fluctuations on gas purchases. Such
instruments include regulated natural gas contracts and over-the-counter swaps
and basis hedges with major energy derivative product specialists. All hedge
transactions are subject to our risk management policy which does not permit
speculative positions. These transactions are accounted for under the hedge
method of accounting. Cash flows from derivative instruments are recognized as
incurred through changes in working capital.
30
Impact of Recent Accounting Pronouncements -- In June 1999, the Financial
Accounting Standards Board issued Statement of Financial Accounting Standards
("SFAS") No. 137, "Accounting for Derivative Instruments and Hedging Activities
- - Deferral of the Effective Date of SFAS No. 133". The Statement amends SFAS No.
133 to defer its effective date to all fiscal quarters of all fiscal years
beginning after June 15, 2000. We have not yet analyzed the impact of adopting
SFAS No. 133 on the financial statements and have not determined the timing of
or method of the adoption of SFAS No. 133. However, the Statement could increase
the volatility of our earnings.
The forward-looking statements discussed in this outlook section involve a
number of risks and uncertainties. Other risks and uncertainties include, but
are not limited to, the general economy, regulatory conditions, the changing
environment of the power generation industry, pricing, the effects of legal and
administrative cases and proceedings, and such other risks and uncertainties as
may be detailed from time to time in our SEC reports and filings.
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
On September 30, 1997, a lawsuit was filed by Indeck North American Power Fund
("Indeck") in the Circuit Court of Cook County, Illinois against Norweb plc. and
certain other parties, including the Company. Some of Indeck's claims relate to
Calpine Gordonsville, Inc.'s acquisition of a 50% interest in Gordonsville
Energy L.P. from Northern Hydro Limited and Calpine Auburndale, Inc.'s
acquisition of a 50% interest in Auburndale Power Plant Partners Limited
Partnership from Norweb Power Services (No. 1) Limited. Indeck claimed that
Calpine Gordonsville, Inc., Calpine Auburndale, Inc. and the Company tortuously
interfered with Indeck's contractual rights to purchase such interests and
conspired with other parties to do so. Indeck is seeking $25.0 million in
compensatory damages, $25.0 million in punitive damages, and the recovery of
attorneys' fees and costs. In April 1999, the court granted Calpine Gordonsville
and Calpine Auburndale's motions to dismiss with prejudice, a decision which has
been appealed by Indeck. The Company is unable to predict the outcome of these
proceedings.
An action was filed against Lockport Energy Associates, L.P. ("LEA") and the New
York Public Service Commission ("NYPSC") in August 1997 by New York State
Electricity and Gas Company ("NYSEG") in the Federal District Court for the
Northern District of New York. NYSEG has requested the Court to direct NYPSC and
the Federal Energy Regulatory Commission (the "FERC") to modify contract rates
to be paid to the Lockport Power Plant. In October 1997, NYPSC filed a
cross-claim alleging that the FERC violated the Public Utility Regulatory
Policies Act of 1978 as amended, ("PURPA") and the Federal Power Act by failing
to reform the NYSEG contract that was previously approved by the NYPSC. Although
it is unable to predict the outcome of this case, in any event, the Company
retains the right to require The Brooklyn Union Gas Company ("BUG") to purchase
the Company's interest in the Lockport Power Plant for $18.9 million, less
equity distributions received by the Company, at any time before December 19,
2001.
The Company is involved in various other claims and legal actions arising out of
the normal course of business. The Company does not expect that the outcome of
these proceedings will have a material adverse effect on the Company's financial
position or results of operations, although no assurance can be given in this
regard.
31
ITEM 2. CHANGE IN SECURITIES
None.
ITEM 3. QUANTITIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Reference is made to Part II, Item 7A, Quantitative and Qualitative Disclosures
About Market Risk, in the Company's Annual Report on Form 10-K for the year
ended December 31, 1998 and to the subheading "Financial Market Risks" under the
heading "Management's Discussion and Analysis of Financial Condition and Results
of Operations" on pages 35-36 of the Company's Annual Report on Form 10-K for
the year ended December 31, 1998.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
ITEM 5. OTHER INFORMATION
None.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Reports on Form 8-K
1. Current report dated October 11, 1999 and filed on October 12, 1999
Item 5. Other Events - Announcement of expected financial results for
the three nine months ended September 20, 1999
Item 7. Exhibits - Press release dated October 11, 1999
2. Current report dated October 22, 1999 and filed on October 23, 1999
Item 5. Other Events - Announcement of financial results for the three
and nine months ended September 30, 1999
Item 7. Exhibits - Press release dated October 22, 1999
(b) Exhibits
The following exhibits are filed herewith unless otherwise indicated:
Exhibit
Number Description
- --------------------------------------------------------------------------------
3.1 -- Amended and Restated Certificate of Incorporation of Calpine
Corporation, a Delaware corporation.(b)
3.2 -- Amended and Restated Bylaws of Calpine Corporation, a Delaware
corporation.(b)
4.1 -- Indenture dated as of February 17, 1994 between the Company and
Shawmut Bank of Connecticut, National Association, as Trustee,
including form of Notes.(a)
4.2 -- Indenture dated as of May 16, 1996 between the Company and Fleet
National Bank, as Trustee, including form of Notes.(c)
4.3 -- Indenture dated as of July 8, 1997 between the Company
and The Bank of New York, as Trustee, including form of Notes.(e)
4.4 -- Indenture dated as of March 31, 1998 between the Company and
The Bank of New York, as Trustee, including form of Notes.(g)
4.5 -- Indenture dated as of March 26, 1999 between the Company and
The Bank of New York, as Trustee, including form of Notes.(h)
32
4.6 -- Indenture dated as of April 21, 1999 between the Company
and The Bank of New York, as Trustee, including form of Notes.(h)
4.7 -- Certificate of Trust of Calpine Capital Trust. (i)
4.8 -- Declaration of Trust of Calpine Capital Trust dated
as of October 4, 1999, between the Company, The Bank of
New York and the Administrative Trustees name therein. (i)
4.9 -- Indenture for HIGH TIDES debentures due 2029 dated as of
November 2, 1999, between the Company and The Bank of
New York, as debenture Trustee. (i)
4.10 -- Form of HIGH TIDES. (i)
4.11 -- Form of HIGH TIDES Debentures due 2029. (i)
4.12 -- Guarantee Agreement dated November 2, 1999 by the Company, as
Guarantor. (i)
10.1 -- Purchase Agreements
10.1.1 -- Purchase and Sale Agreement dated March 27, 1997 for the purchase
and sale of shares of Enron/Dominion Cogen Corp. Common Stock
among Enron Power Corporation and Calpine Corporation.(f)
10.1.2 -- Stock Purchase and Redemption Agreement dated March 31, 1998,
among Dominion Cogen, Inc. Dominion Energy, Inc. and Calpine
Finance.(f)
10.2 -- Other Agreements
10.2.1 -- Calpine Corporation Stock Option Program and forms of agreements
thereunder.(a)
10.2.2 -- Calpine Corporation 1996 Stock Incentive Plan and forms of agreements
thereunder.(b)
10.2.3 -- Calpine Corporation Employee Stock Purchase Plan and forms of
agreements thereunder.(b)
10.2.4 -- Amended and Restated Employment Agreement between Calpine Corporation
and Mr. Peter Cartwright.(b)
10.2.5 -- Executive Vice President Employment Agreement between Calpine
Corporation and Ms. Ann B. Curtis.(*)
10.2.6 -- Senior Vice President Employment Agreement between Calpine Corporation
and Mr. Ron A. Walter.(*)
10.2.7 -- Senior Vice President Employment Agreement between Calpine Corporation
and Mr. Robert D. Kelly.(*)
10.2.8 -- Executive Vice President Employment Agreement between Calpine
Corporation and Mr. Thomas R. Mason.(*)
10.2.9 -- First Amended and Restated Consulting Contract between Calpine
Corporation and Mr. George J. Stathakis.(b)
10.3 -- Form of Indemnification Agreement for directors and officers.(b)
21.1 -- Subsidiaries of the Company.(c)
27.0 -- Financial Data Schedule.* ___________
(a) Incorporated by reference to Registrant's Registration Statement on Form
S-1 (Registration Statement No. 33-73160).
(b) Incorporated by reference to Registrant's Registration Statement on Form
S-1 (Registration Statement No. 333-07497).
(c) Incorporated by reference to Registrant's Current Report on Form 8-K dated
August 29, 1996 and filed on September 13, 1996.
(d) Incorporated by reference to Registrant's Annual Report on Form 10-K dated
December 31, 1996, filed on March 27, 1996.
(e) Incorporated by reference to Registrant's Quarterly Report on Form 10-Q
dated June 30, 1997 and filed on August 14, 1997.
(f) Incorporated by reference to Registrant's Current Report on Form 8-K dated
March 31, 1998 and filed on April 14, 1998.
33
(g) Incorporated by reference to Registrant's Registration Statement on Form
S-4, filed on August 10, 1998 (Registration Statement No. 333-61047).
(h) Incorporated by reference to Registrant's Form 424B4 filed on March 26,
1999 with the Securities and Exchange Commission.
(i) Incorporated by reference to Registrant's Form 424B4 filed on October 29,
1999 with the Securities and Exchange Commission.
* Filed herewith.
Exhibit 27 Financial Data Schedule
34
SIGNATURES
Pursuant to the requirements of the Securities and Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
CALPINE CORPORATION
By: /s/ Ann B. Curtis Date: November 12, 1999
-------------------------
Ann B. Curtis
Executive Vice President
(Chief Financial Officer)
By: /s/ Charles B. Clark, Jr. Date: November 12, 1999
--------------------------
Charles B. Clark, Jr.
Vice President and Corporate Controller
(Chief Accounting Officer)
35